Configuration for olefins production

ABSTRACT

Processes herein may be used to thermally crack various hydrocarbon feeds, and may eliminate the refinery altogether while making the crude to chemicals process very flexible in terms of crude. In embodiments herein, crude is progressively separated into at least light and heavy fractions. Depending on the quality of the light and heavy fractions, these are routed to one of three upgrading operations, including a fixed bed hydroconversion unit, a fluidized catalytic conversion unit, or a residue hydrocracking unit that may utilize an ebullated bed reactor. Products from the upgrading operations may be used as feed to a steam cracker.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application, pursuant to 35 U.S.C. § 119(e), claims priority toU.S. Provisional Application Ser. Nos. 62/819,270, 62/819,282,62/819,247, 62/819,229, and 62/819,315, each filed Mar. 15, 2019, andeach of which is herein incorporated by reference in its entirety.

FIELD OF THE DISCLOSURE

Embodiments herein relate to processes and systems for producingpetrochemicals, such as olefins and aromatics, from crude oil and lowvalue heavy hydrocarbon streams.

BACKGROUND

High-boiling compounds in crude oil may cause significant operationalissues if they are sent to a steam cracker. High boiling compounds havea propensity to form coke, due in large part to their high asphaltenecontent. Therefore, the high boiling compounds are typically removedbefore sending the lighter fractions to different petrochemicals units,such as a steam cracker or an aromatics complex. The removal process,however, increases the capital cost of the overall process and lowersprofitability, as the removed high-boiling compounds can only be sold aslow-value fuel oil. In addition, conversion of vacuum residue withoutsignificant formation of HPNAs that are detrimental to steam crackerfurnaces downstream of the process has been a challenge to date.

U.S. Pat. No. 3,617,493 describes a process in which crude oil is sentto the convection section of a steam cracker and then to a separationzone, where the portion of the feed boiling below about 450° F. isseparated from the rest of the feed and then sent, with steam, into thehigh temperature portion of the steam cracker and subjected to crackingconditions.

U.S. Pat. No. 4,133,777 teaches a process in which feed oil initiallyflows downwardly in trickle flow through a fixed bed of HDM catalysts,and then passes downwardly through a fixed bed of promoted catalystscontaining selected GROUP VI and GROUP VIII metals, with very littlehydrocracking occurring in this combination process.

U.S. Pat. No. 5,603,824 disclosed a process of upgrading a waxyhydrocarbon feed mixture containing sulfur compounds which boils in thedistillate range, in order to reduce sulfur content and 85% point whilepreserving the high octane of naphtha by-products and maximizingdistillate yield. The process employs a single, downflow reactor havingat least two catalyst beds and an inter-bed redistributor between thebeds. The top bed contains a hydrocracking catalyst, preferably zeolitebeta, and the bottom bed contains a dewaxing catalyst, preferably ZSM-5.

U.S. Pat. No. 3,730,879 discloses a two-bed catalytic process for thehydrodesulfurization of crude oil or a reduced fraction, in which atleast 50 percent of the total pore volume of the first-bed catalyticconsists of pores in the 100-200 Angstrom diameter range.

U.S. Pat. No. 3,830,720 discloses a two-bed catalytic process forhydrocracking and hydrodesulfurizing residual oils, in which asmall-pore catalyst is disposed upstream of a large-pore catalyst.

U.S. Pat. No. 3,876,523 describes a novel catalyst and a process forcatalytically demetalizing and desulfurizing hydrocarbon oils comprisingresidual fractions. The process described therein utilizes a catalystcomprising a hydrogenation component, such as cobalt and molybdenumoxides, composited on an alumina. Although this catalyst is highlyeffective for demetalization of residual fractions and has goodstability with time on stream, its utility is remarkably improved whenthis catalyst is employed in a particular manner in combination with asecond catalyst having different critical characteristics. A catalyst ofthe type described in U.S. Pat. No. 3,876,523 will be referred as afirst catalyst, it being understood that this first catalyst is to besituated upstream of the second catalyst having differentcharacteristics.

U.S. Pat. No. 4,153,539 discloses that improved hydrogen utilizationand/or higher conversions of desired product is obtained inhydrotreating or hydrocracking processes when using amphora particlesfor hydrotreating of light hydrocarbon fractions, catalytic reforming,fixed-bed alkylation processes, and the like.

U.S. Pat. No. 4,016,067 discloses that hydrocarbon oils, preferablyresidual fractions, are catalytically hydroprocessed to very effectivelyremove both metals and sulfur and with particularly slow aging of thecatalyst system by contacting the oil sequentially with two catalysts ofdifferent characteristics. The first catalyst, located upstream of thesecond catalyst, is characterized by having at least 60% of its porevolume in pores greater than 100 A. in diameter and othercharacteristics hereinafter specified. The second catalyst, locateddownstream with respect to the first catalyst, is characterized byhaving a major fraction of its pore volume in pores less than 100 A. indiameter.

The dual catalyst apparatus of U.S. Pat. No. 4,016,067 is used todemetallize and/or desulfurize any hydrocarbon oil that has metalsand/or sulfur content-undesirably high for a particular application. Thedual catalyst apparatus is particularly effective for preparing lowmetals and/or low sulfur content feedstocks for catalytic cracking orfor coking. In the processing to remove metals and sulfur, andhydrocarbon oil also is concomitantly enriched in hydrogen, making it aneven more suitable chargestock for either of these processes.

In general, these and other prior processes for converting whole crudestypically convert less than 50 percent of the crude to the moredesirable end products, including petrochemicals such as ethylene,propylene, butenes, pentenes, and light aromatics, for example.Generally, 20 percent of the whole crude is removed up front inprocessing, removing the heaviest components that are hard to convert.About another 20 percent of the whole crude is typically converted topyrolysis oil, and about 10 percent is over-converted to methane.

SUMMARY

A process for converting whole crudes and other heavy hydrocarbonstreams to produce olefins and/or aromatics, the process including:separating a whole crude into at least a light boiling fraction, amedium boiling fraction, and a high boiling residue fraction;hydrocracking the high boiling residue fraction in a first hydrocrackingsystem to produce a hydrocracked effluent; separating the hydrocrackedeffluent in an integrated separation device to produce an ultra-lowsulfur fuel oil and a hydroprocessed fraction; combining the mediumboiling fraction and the hydroprocessed fraction; destructivelyhydrogenating the combined medium boiling fraction and hydroprocessedfraction in a second hydroprocessing system to produce a steam crackerfeedstream; feeding the steam cracker feedstream and the light boilingfraction to a steam cracker to convert hydrocarbons therein into one ormore light olefins and a pyrolysis oil.

A system for converting whole crudes and other heavy hydrocarbon streamsto produce olefins, the system including: a first integrated separationdevice for separating a hydrocarbon feedstock into at least a lightboiling fraction, a medium boiling fraction, and a high boiling residuefraction; a first hydroprocessing system configured for hydrotreatingthe high boiling residue fraction and producing a hydrotreated effluent;a second integrated separation device configured for separating thehydrotreated and hydrocracked effluent and producing an ultra-low sulfurfuel oil and a hydroprocessed fraction; a second hydroprocessing systemconfigured for hydrocracking the hydroprocessed fraction and producing asteam cracker feedstream; a steam cracker unit for converting the steamcracker feedstream and the light boiling fraction into one or more lightolefins and a pyrolysis oil.

Other aspects and advantages will be apparent from the followingdescription and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

FIG. 2 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

FIG. 3 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

FIG. 4 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

FIG. 5 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

DETAILED DESCRIPTION

As used herein, the term “petrochemicals” refers to hydrocarbonsincluding light olefins and diolefins and C6-C8 aromatics.Petrochemicals thus refers to hydrocarbons including ethylene,propylene, butenes, butadienes, pentenes, pentadienes, as well asbenzene, toluene, and xylenes. Referring to a subset of petrochemicals,the term “chemicals,” as used herein, refers to ethylene, propylene,butadiene, 1-butene, isobutylene, benzene, toluene, and para-xylenes.

Hydrotreating is a catalytic process, usually carried out in thepresence of free hydrogen, in which the primary purpose when used toprocess hydrocarbon feedstocks is the removal of various metalcontaminants (e.g., arsenic), heteroatoms (e.g., sulfur, nitrogen andoxygen), and aromatics from the feedstock. Generally, in hydrotreatingoperations cracking of the hydrocarbon molecules (i.e., breaking thelarger hydrocarbon molecules into smaller hydrocarbon molecules) isminimized. As used herein, the term “hydrotreating” refers to a refiningprocess whereby a feed stream is reacted with hydrogen gas in thepresence of a catalyst to remove impurities such as sulfur, nitrogen,oxygen, and/or metals (e.g. nickel, or vanadium) from the feed stream(e.g. the atmospheric tower bottoms) through reductive processes.Hydrotreating processes may vary substantially depending on the type offeed to a hydrotreater. For example, light feeds (e.g. naphtha) containvery little and few types of impurities, whereas heavy feeds (e.g. ATBs)typically possess many different heavy compounds present in a crude oil.Apart from having heavy compounds, impurities in heavy feeds are morecomplex and difficult to treat than those present in light feeds.Therefore, hydrotreating of light feeds is generally performed at lowerreaction severity, whereas heavy feeds require higher reaction pressuresand temperatures.

Hydrocracking refers to a process in which hydrogenation anddehydrogenation accompanies the cracking/fragmentation of hydrocarbons,e.g., converting heavier hydrocarbons into lighter hydrocarbons, orconverting aromatics and/or cycloparaffins(naphthenes) into non-cyclicbranched paraffins.

“Conditioning” and like terms as used herein refers to conversion ofhydrocarbons by one or both of hydrocracking and hydrotreating.“Destructive hydrogenation” and like terms refers to cracking of thehydrocarbon molecular bonds of a hydrocarbon, and the associatedhydrogen saturation of the remaining hydrocarbon fragments, which cancreate stable lower boiling point hydrocarbon oil products, and may beinclusive of both hydrocracking and hydrotreating.

“API gravity” refers to the gravity of a petroleum feedstock or productrelative to water, as determined by ASTM D4052-11.

The integration of conditioning, fractionation, and steam cracking mayresult in a highly efficient facility, and in some embodiments mayconvert greater than 55%, greater than 60%, greater than 65%, greaterthan 70%, greater than 75%, greater than 80%, or greater than 85% of thewhole crude to petrochemicals. In other embodiments, the integration ofconditioning, fractionation, and steam cracking may result in a highlyefficient facility, and in some embodiments may convert greater than55%, greater than 60%, greater than 65%, greater than 70%, greater than75%, greater than 80% or greater than 85% of the whole crude tochemicals. Embodiments herein may thus provide systems and processes forconditioning feeds including even the heaviest, most undesirableresiduum components into components that can be vaporized and passedinto the radiant section of a steam cracker, substantially improvingover the low petrochemical conversion of prior processes.

Embodiments herein relate to processes and systems that take crude oiland/or low value heavy hydrocarbons as feed and produces petrochemicals,such as light olefins and diolefins (ethylene, propylene, butadiene,and/or butenes) and aromatics. More specifically, embodiments herein aredirected toward methods and systems for making olefins and aromatics bythermal cracking of a pre-conditioned crude oil or condensate. Processesherein may condition the residuum fraction of whole crude oils andnatural condensates to produce feedstocks useful as a steam crackerfeedstock.

Hydrocarbon mixtures useful in embodiments disclosed herein may includevarious hydrocarbon mixtures having a boiling point range, where the endboiling point of the mixture may be greater than 500° C., such asgreater than 525° C., 550° C., or 575° C. The amount of high boilinghydrocarbons, such as hydrocarbons boiling over 550° C., may be aslittle as 0.1 wt %, 1 wt % or 2 wt %, but can be as high as 10 wt %, 25wt %, 50 wt % or greater. The description is explained with respect tocrude oil, such as whole crude oil, but any high boiling end pointhydrocarbon mixture can be used. However, processes disclosed herein canbe applied to crudes, condensates and hydrocarbon with a wide boilingcurve and end points higher than 500° C. Such hydrocarbon mixtures mayinclude whole crudes, virgin crudes, hydroprocessed crudes, gas oils,vacuum gas oils, heating oils, jet fuels, diesels, kerosenes, gasolines,synthetic naphthas, raffinate reformates, Fischer-Tropsch liquids,Fischer-Tropsch gases, natural gasolines, distillates, virgin naphthas,natural gas condensates, atmospheric pipestill bottoms, vacuum pipestillstreams including bottoms, wide boiling range naphtha to gas oilcondensates, heavy non-virgin hydrocarbon streams from refineries,vacuum gas oils, heavy gas oils, atmospheric residuum, hydrocracker wax,and Fischer-Tropsch wax, among others. In some embodiments, thehydrocarbon mixture may include hydrocarbons boiling from the naphtharange or lighter to the vacuum gas oil range or heavier.

When the end boiling point of the hydrocarbon mixture is high, such asover 550° C., the hydrocarbon mixture cannot be processed directly in asteam pyrolysis reactor to produce olefins. The presence of these heavyhydrocarbons results in the formation of coke in the reactor, where thecoking may occur in one or more of the convection zone preheating coilsor superheating coils, in the radiant coils, or in transfer lineexchangers, and such coking may occur rapidly, such as in few hours.Whole crude is not typically cracked commercially, as it is noteconomical. It is generally fractionated, and only specific cuts areused in a steam pyrolysis heater to produce olefins. The remainder isused in other processes. The cracking reaction proceeds via a freeradical mechanism. Hence, high ethylene yield can be achieved when it iscracked at high temperatures. Lighter feeds, like butanes and pentanes,require a high reactor temperature to obtain high olefin yields. Heavyfeeds, like gas oil and vacuum gas oil (VGO), require lowertemperatures. Crude contains a distribution of compounds from butanes toVGO and residue (material boiling over 550° C.). Subjecting the wholecrude without separation at high temperatures produces a high yield ofcoke (byproduct of cracking hydrocarbons at high severity) and plugs thepyrolysis reactor. The steam pyrolysis reactor has to be periodicallyshut down and the coke is cleaned by steam/air decoking. The timebetween two cleaning periods when the olefins are produced is called runlength. When whole crude is cracked without separation, coke can depositin the convection section coils (vaporizing the fluid), in the radiantsection (where the olefin producing reactions occur) and/or in thetransfer line exchanger (where the reactions are stopped quickly bycooling to preserve the olefin yields).

Processes and systems according to embodiments herein may include a feedpreparation section, a crude conditioning section, an aromatics complex,and a steam cracker. The feed preparation section may include adesalter, for example.

The desalted crude is then conditioned and processed such that crackablefeed is being sent to the steam cracker and/or the aromatics complex.The conditioning section may allow an operator to maximize the chemicalsyield while maintaining a reasonable decoking frequency of the furnaces.Another objective of the crude conditioning unit is to ensure completeor essentially complete (95%+) conversion of asphaltenes to lowerboiling point components that enhance the chemicals yield while reducingthe formation of heavy polynuclear aromatics (HPNAs).

Processes according to embodiments herein may thus convert heavierfractions of crude oil into high-value petrochemicals and may minimizethe amount of hydrocarbons sent to a fuel oil pool, which substantiallyincreases profitability. The small fuel oil pool that is produced mayalso be upgraded into a low-sulfur, IMO 2020 compliant fuel oil, furtherincreasing the value of the products.

As noted above, high-boiling compounds in the crude oil may causesignificant operational issues if they are sent to a steam cracker, dueto their propensity to form coke, mainly because of their highasphaltene content. Therefore, the high boiling compounds are typicallyremoved before sending the lighter fractions to different petrochemicalsunits, such as the steam cracker and aromatics complex. The removalprocess increases the capital cost of the overall process and lowersprofitability, as the removed high-boiling compounds can only be sold aslow-value fuel oil. In addition, conversion of vacuum residue withoutsignificant formation of HPNAs that are detrimental to steam crackerfurnaces downstream of the process has been a challenge to date in theindustry. Processes and systems according to embodiments herein mayovercome these challenges.

The configurations of systems and processes for the conversion of wholecrudes and heavy hydrocarbons according to embodiments described hereinmay efficiently handle resid conversion while maximizing thepetrochemicals conversion and maintaining lower coking propensity in thesteam cracker. This is achieved by using one or more integratedseparation devices (ISD) and/or crude conditioning processes.

The upgraded crude streams from the one or more crude conditioningunits, such as from a fixed bed crude conditioning unit and ahydrocracker, are suitable feedstocks for the steam cracker as well asan aromatic complex. Such may lead to decreasing the overall processyields of low value fuel oil and increasing the yields of high valueolefins and aromatics, such as benzene, toluene, and xylenes (BTX).

Separation of various fractions, such as a low boiling fraction (a 160°C.− fraction, for example) and a high boiling fraction (a 160° C.+fraction, for example), or such as a low, middle and high boilingfractions (a 160° C.− fraction, a 160-490° C. fraction, and a 490° C.+fraction, for example) may enhance the capital efficiently and operatingcosts of the processes and systems disclosed herein. While referring tothree cuts in many embodiments herein, it is recognized by the presentinventors that condensates, typically having a small amount of highboiling components, and whole crudes, having a greater quantity of highboiling components, may be processed differently. Accordingly, one, two,three or more individual cuts can be performed for the wide boilingrange petroleum feeds, and each cut can be processed separately atoptimum conditions.

Separation of the whole crude into the desired fractions may beperformed using one or more separators (distillation columns, flashdrums, etc.). In some embodiments, separation of the petroleum feeds maybe performed in an integrated separation device (ISD), such as disclosedin US20130197283, which is incorporated herein by reference. In the ISD,an initial separation of a low boiling fraction is performed in the ISDbased on a combination of centrifugal and cyclonic effects to separatethe desired vapor fraction from liquid. An additional separation stepmay then be used to separate a middle boiling fraction from high boilingcomponents.

Typically, hydrocarbon components boiling above 490° C. containasphaltenes and Conradson Carbon Residue, and thus need to be processedappropriately, as described further below. While embodiments aredescribed as including a fraction below about 90° C.-250° C., such as a160° C.− fraction and a fraction above about 400° C.-560° C., such as a490° C.+ fraction, it is noted that the actual cut points may be variedbased on the type of whole crude or other heavy fractions beingprocessed. For example, for a crude containing a low metals or nitrogencontent, or a large quantity of “easier-to-process” components boiling,for instance, at temperatures up to 525° C., 540° C., or 565° C., it maybe possible to increase the mid/high cut point while still achieving thebenefits of embodiments herein. Similarly, the low/mid cut point may beas high as 220° C. in some embodiments, or as high as 250° C. in otherembodiments. Further, it has been found that a low/mid cut point ofabout 160° C. may provide a benefit for sizing and operation of thereactors, such as a fixed bed conditioning reactor, for conditioning themid fraction hydrocarbons (middle cut). Further still, for some feeds,such as condensate, the low/mid cut point may be as high as 565° C. Theability to vary the cut points may add flexibility to process schemesaccording to embodiments herein, allowing for processing of a widevariety of feeds while still producing the product mixture desired.

Accordingly, in some embodiments, the light cut may include hydrocarbonshaving a boiling point up to about 90° C. (e.g., a 90° C.− fraction), upto about 100° C., up to about 110° C., up to about 120° C., up to about130° C., up to about 140° C., up to about 150° C., up to about 160° C.,up to about 170° C., up to about 180° C., up to about 190° C., up toabout 200° C., up to about 210° C., up to about 220° C., up to about230° C., up to about 240° C., up to about 250° C. (e.g., a 250° C.−fraction), up to about 300° C., up to about 350° C., up to about 400°C., up to about 500° C., or up to about 565° C. Embodiments herein alsocontemplate the light cut being hydrocarbons having boiling points up totemperatures intermediate the aforementioned ranges.

Depending upon the fractionation mechanism used, the light hydrocarbon“cut” may be relatively clean, meaning the light fraction may not haveany substantial amount (>1 wt % as used herein) of compounds boilingabove the intended boiling temperature target. For example, a 160° C.−cut may not have any substantial amount of hydrocarbon compounds boilingabove 160° C. (i.e., >1 wt %). In other embodiments, the intended target“cut” temperatures noted above may be a 95% boiling point temperature,or in other embodiments as an 85% boiling point temperature, such as maybe measured using ASTM D86 or ASTM D2887, or a True Boiling Point (TBP)analysis according to ASTM D2892, for example, and ASTM D7169 for heavystreams, such as those boiling above about 400° C. In such embodiments,there may be up to 5 wt % or up to 15 wt % of compounds above theindicated “cut” point temperature. For many whole crudes, the low/midcut point may be such that the light boiling fraction has a 95% boilingpoint temperature in the range from about 90° C. to about 250° C. Forother feeds, however, such as condensate, the light boiling fraction mayhave a 95% boiling point temperature in the range from about 500° C. toabout 565° C., for example.

In some embodiments, the middle cut may include hydrocarbons having aboiling point from a lower limit of the light cut upper temperature(e.g., 90° C., 100° C., 110° C., 120° C., 130° C., 140° C., 150° C.,160° C., 170° C., 180° C., 190° C., 200° C., 210° C., 220° C., 230° C.,240° C., 250° C., 300° C., 350° C., or 400° C., for example) to an upperlimit of hydrocarbons having a boiling point up to about 350° C., up toabout 375° C., up to about 400° C., up to about 410° C., up to about420° C., up to about 430° C., up to about 440° C., up to about 450° C.,up to about 460° C., up to about 480° C., up to about 490° C., up toabout 500° C., up to about 520° C., up to about 540° C., up to about560° C., or up to about 580° C. As used herein, for example, a middlecut having a lower limit of 160° C. and an upper limit of 490° C. may bereferred to as a 160° C. to 490° C. cut or fraction. Embodiments hereinalso contemplate the middle cut being hydrocarbons having boiling pointsfrom and/or up to temperatures intermediate the aforementioned ranges.

Depending upon the fractionation mechanism, the hydrocarbon “cut” forthe middle cut may be relatively clean, meaning the middle cut may nothave any substantial amount (>1 wt %) of compounds boiling below and/ormay not have any substantial amount (>1 wt %) of compounds boiling abovethe intended boiling temperature target limits. For example, a 160° C.to 490° C. cut may not have any substantial amount of hydrocarboncompounds boiling below 160° C. or above 490° C. In other embodiments,the intended target “cut” temperatures noted above may be a 5 wt % or 15wt % boiling point temperature on the lower limit and/or a 95% or 85%boiling point temperature on the upper limit, such as may be measuredusing ASTM D86 or ASTM D2887, or a True Boiling Point (TBP) analysisaccording to ASTM D2892, for example, and ASTM D7169 for heavy streams,such as those boiling above about 400° C. In such embodiments, there maybe up to 5 wt % or up to 15 wt % of compounds above and/or below the“cut” point temperature, respectively.

In some embodiments, the heavy cut may include hydrocarbons having aboiling point above about 350° C., above about 375° C., above about 400°C. (e.g., a 400° C.+ fraction), above about 420° C., above about 440°C., above about 460° C., above about 480° C., above about 490° C., aboveabout 500° C., above about 510° C., above about 520° C., above about530° C., above about 540° C., above about 560° C., above about 580° C.,above about 590° C., above about 600° C. (e.g., a 600° C.+ fraction), orabove about 700° C. Embodiments herein also contemplate the heavy cutbeing hydrocarbons having boiling points above temperatures intermediatethe aforementioned temperatures.

Depending upon the fractionation mechanism, the heavy hydrocarbon “cut”may be relatively clean, meaning the heavy fraction may not have anysubstantial amount (>1 wt %) of compounds boiling below the intendedboiling temperature target. For example, a 490° C.+ cut may not have anysubstantial amount of hydrocarbon compounds boiling below 490° C. Inother embodiments, the intended target “cut” temperatures noted abovemay be a 95% boiling point temperature, or in other embodiments as an85% boiling point temperature, such as may be measured using ASTM D86 orASTM D2887, or a True Boiling Point (TBP) analysis according to ASTMD2892, for example, and ASTM D7169 for heavy streams, such as thoseboiling above about 400° C. In such embodiments, there may be up to 5 wt% or up to 15 wt % of compounds, respectively, below the “cut” pointtemperature.

While examples below are given with respect to limited temperatureranges, it is envisioned that any of the temperature ranges prescribedabove can be used in the processes described herein. Further, withrespect to cut points, those referred to in the examples below may beclean, as described above, or may refer to 5% or 15% boilingtemperatures for lower limits, or may refer to 85% or 95% boilingtemperatures for upper limits.

Following fractionation, the light cut, such as a 160° C.− cut, may befed to a steam cracker section of the system with or without furtherprocessing. The light cut fed to the steam cracker section may includelight naphtha and lighter hydrocarbons, for example, and in someembodiments may include heavy naphtha boiling range hydrocarbons.

The mid-range hydrocarbon cut may be conditioned using one or more fixedbed reactors, such as hydrotreating and/or hydrocracking reactors, eachof which may destructively hydrogenate the hydrocarbons in the mid-cut.The conditioning reactors may include catalysts for metals removal,sulfur removal, nitrogen removal, and the conditioning in these reactorsmay overall add hydrogen to the hydrocarbon components, making themeasier to process downstream to produce petrochemicals. The fixed bedcatalyst systems in the mid-cut conditioning zone, for example, maycontain different layers of demetalizing, destructive hydrogenation andmesoporous zeolite hydrocracking catalysts to optimize the conversion ofthe heavy materials to a balance between a highly paraffinic stream thatis suitable for olefins production and a rich in aromatics stream thatis suitable for aromatics production.

In some embodiments, it may be desirable to further separate the mid-cutinto a low-mid cut and a high-mid cut. For example, a mid-cut having aboiling range from 160° C. to 490° C. may be divided into a low-mid cuthaving a boiling range from about 160° C. to about 325° C. and ahigh-mid cut having a boiling range from about 325° C. to about 490° C.The conditioning trains may thus be configured to more selectivelyconvert the hydrocarbon components in the respective low and high midcuts to the desired conditioned effluents, where each train may beconfigured based on preferred catalysts to destructively hydrogenate thehydrocarbons therein, reactor sizing for expected feed volumes andcatalyst lifetime, as well as operating conditions to achieve thedesired conversions to naphtha range containing steam crackerfeedstocks. Similarly, division of the mid cut into three or moresub-cuts is also contemplated.

The hydrocarbons in a heavy cut may also be conditioned using one ormore fixed bed reactors, slurry reactors, or ebullated bed reactors.Conditioning of the heavy cut, such as 490° C.+ hydrocarbons, may beperformed, for example, in a residue hydrocracker, and may enhance theconversion of low value streams to high value petrochemical products viasteam cracking. Residue hydrocracking may be performed, for example, ina fixed bed residue hydrocracker, an ebullated bed reactor, such as anLC-FINING or LC-MAX reactor system, as well as slurry reactors, such asLC-SLURRY reactors, each available from Chevron Lummus Global. It isrecognized, however, that the lifetime of destructive hydrogenationand/or hydrocracking catalysts may be negatively impacted by heaviercomponents, such as where the feed includes components boiling above565° C., for example. Similar to the mid-cut, division of the heavy cutinto one or more sub-cuts is also contemplated.

The crude conditioning system is designed to achieve four (4) goals.First, the crude conditioning section may be used to increase theconcentration of paraffins and naphthenes in the crude. Second, theconditioning section may decrease the concentration of polynucleararomatic hydrocarbons (PNAs) in the crude. Third, the conditioningsection may reduce the final boiling point (FBP) of the crude to below540° C. And, fourth, the conditioning section may minimize the vacuumresidue fraction of the crude oil.

Embodiments herein, when conditioning the middle and/or heavy fractions,may target conversion of the heavier hydrocarbons to form hydrocarbonslighter than diesel, for example. The hydrotreating and hydrocrackingcatalysts and operating conditions may thus be selected to target theconversion of the hydrocarbons, or the hydrocarbons in the in therespective fractions, to primarily (>50 wt %) naphtha rangehydrocarbons. In one or more embodiments, hydrotreating andhydrocracking catalysts and operating conditions may thus be selected totarget the conversion of the hydrocarbons, or the hydrocarbons in the inthe respective fractions, to primarily (>50 wt %) steam crackableproducts. The use of catalysts and operating conditions in theconditioning section to target lighter hydrocarbon products may enhancethe operability of the steam cracker and the production of chemicals.

In some embodiments, conditioning of the heavy cut, such as a 490° C.+cut, may result in conversion of at least 70 wt % of the compoundsboiling in excess of 565° C. to lighter boiling compounds. Otherembodiments may result in conversion of greater than 75 wt %, greaterthan 80 wt %, or greater than 85 wt % of the compounds boiling in excessof 565° C. to lighter boiling compounds.

In some embodiments, conditioning of the middle cut (or heavy cut for atwo-cut embodiment), such as a 160° C. to 490° C. cut, may result inconversion of greater than 50 wt % of the hydrocarbons therein tonaphtha range hydrocarbons. In other embodiments, conditioning of themiddle cut may result in conversion of greater than 55 wt %, greaterthan 60 wt %, or greater than 65 wt %, or greater than 70 wt % of thehydrocarbons therein to naphtha range hydrocarbons.

In some embodiments, collective conditioning of the middle cut and theheavy cut may result in an overall conversion of greater than 50 wt % ofthe hydrocarbons therein to naphtha range hydrocarbons. In otherembodiments, conditioning of the middle cut and the heavy cut may resultin conversion of greater than 55 wt %, greater than 60 wt %, or greaterthan 65 wt % of the hydrocarbons therein to naphtha range hydrocarbons.

As a result of such initial separations and conditioning, feeds to thesteam cracker may be fed, in some embodiments, directly to the steamcracker without further processing. The light cut, having preferredproperties, including one or more of boiling point, API, BMCI, hydrogencontent, nitrogen content, sulfur content, viscosity, MCRT, or totalmetals content, may be fed directly to the steam cracker followingseparations in some embodiments. Effluents from the middle cutconditioning may also be fed directly to the steam cracker according toembodiments herein. Likewise, effluents from the heavy cut conditioningmay be fed directly to the steam cracker in some embodiments.

The conditioning of the respective fractions as described herein mayallow for the steam cracker, even while processing multiple feeds ofvarying boiling point ranges, to run for an extended period of time. Insome embodiments, the steam cracker may be able to run for anuninterrupted run length of at least three years; at least four years inother embodiments; and at least five years in yet other embodiments.

Further, the initial hydrocarbon cut points, reactor sizes, catalysts,etc. may be adjusted or configured such that a run time of the steamcracker operations and conditioning processes may be aligned. Forexample, in the configuration of FIG. 1 , further described below, awhole crude oil may be conditioned and the conditioned crude may then besteam cracked. The catalysts, reactor sizes, and conditions may beconfigured such that a run time of the conditioning unit is aligned withthe run time of the steam cracker. Catalyst volumes, catalyst types, andreaction severity may all play a role in determining conditioning unitrun times. Further, the extent of conditioning of the heavierhydrocarbons in the crude may impact coking in the thermal cracker. Tomaximize plant uptime, embodiments herein contemplate design andconfiguration of the overall system such that the conditioning systemhas a similar anticipated run time as the steam cracker for a givenfeedstock or a variety of anticipated feedstocks. Further, embodimentsherein contemplate adjustment of reaction conditions (T, P, spacevelocity, etc.) in the conditioning section and/or the steam crackerbased on a feedstock being processed, such that a run time of theconditioning section and the steam cracker are similar or aligned.

Alignment of run times may result in minimal downtime, such as where acatalyst turnover in a conditioning reactor is conducted concurrentlywith decoking of the steam cracker. Where the conditioning systemincludes multiple reactors or types of reactors, alignment of the runtimes may be based on the expected steam cracker performance. Further,where a hydrotreater, for example, may have a significantly longer runtime than a hydrocracker in the conditioning section, parallel reactortrains and/or bypass processing may be used such that the overall runtimes of the conditioning and steam cracking units may be aligned.

Bypass processing may include, for example, temporarily processing a490° C.+ cut in a reactor that normally processes a lighter feedstock.The heavier feedstock is anticipated to have more severe conditions andshorter catalyst life, and thus temporarily processing the heavies in amid-range hydrocarbons conditioning reactor during a heavies catalystchange may allow the whole crude feed to continue to be fed to the steamcracker, without a shutdown, while the heavies conditioning reactorcatalyst is replaced. Configuration of the mid-range conditioningreactors may also take into account the anticipated bypass processingwhen designing the overall system for aligned run times.

Referring now to FIG. 1 , a simplified process flow diagram of a systemfor converting whole crudes and heavy hydrocarbons according toembodiments herein is illustrated.

A wide boiling range heavy hydrocarbon feed, such as a desalted crude 1,may be fed to a fixed bed conditioning system 2, such as one or morehydrotreating and/or hydrocracking reactors, to produce a highlyparaffinic stream 4 suitable for processing in the steam crackingsection 7. The steam cracker section 7 may produce one or more chemicalstreams 23, such as ethylene, propylene, and butenes, among others, aswell as a higher boiling pyrolysis oil fraction 25.

Recognizing that fixed bed conditioning may be detrimental to the lightends of some feedstocks, it may be desirable to perform an initialseparation, such that the heavier components are conditioned for steamcracker feed while the lighter components, already suitable for steamcracker feed, are not further conditioned. Referring now to FIG. 2 , asimplified process flow diagram of a system for converting whole crudesand heavy hydrocarbons according to embodiments herein is illustratedwhere like numerals represent like parts.

A wide boiling range heavy hydrocarbon feed, such as a desalted crude 1,may be fed to a separation system 3. Separation system 3 may be anintegrated separation device (ISD), as described above and includingseparation and heat integration, for example. In separation system 3,the desalted crude 1 may be separated into two fractions, including (a)a 160° C.− fraction 5 that does not require any conditioning and can beused as feed to the steam cracker section 7; and (b) a 160° C.+ fraction8 that may be upgraded in a conditioning section 27 to produce lighterhydrocarbons, such as a highly paraffinic stream 14 suitable forprocessing in the steam cracking section 7. Other cut points may also beused to route the desired fractions and hydrocarbons therein to desiredunits for conditioning and/or cracking. The processing of the feeds inthe steam cracker section may produce one or more chemical streams 23,such as ethylene, propylene, and butenes, among others, as well as ahigher boiling pyrolysis oil fraction 25.

Referring now to FIG. 3 , a simplified process flow diagram of a systemfor converting whole crudes and heavy hydrocarbons according toembodiments herein is illustrated, where like numerals represent likeparts. In this embodiment, the desalted whole crude is processed similarto that as described above for FIG. 2 .

A wide boiling range heavy hydrocarbon feed, such as a desalted crude 1,may be fed to a separation system 3. Separation system 3 may be anintegrated separation device (ISD), as described above and includingseparation and heat integration, for example. In separation system 3,the desalted crude 1 may be separated into two fractions, including (a)a 160° C.− fraction 5 that does not require any conditioning and can beused as feed to the steam cracker section 7; and (b) a 160° C.+ fraction8 that may be upgraded in a first conditioning section 27. The firstconditioning system 27 may be designed with one or more hydrotreatingand/or hydrocracking reactors to at least partially convert the 160° C.+fraction and to produce a conditioned hydrocarbon stream 28. Stream 28may then bed fed to a second separation system 29, such as a second ISD,which may separate the lighter, conditioned hydrocarbons in stream 28from heavier hydrocarbons that may be unsuitable for processing in thesteam cracker. The heavy hydrocarbons may be removed from the separationsystem 29 as an ultra-low sulfur fuel oil (ULSFO) stream 30. In someembodiments, separation system 28 may provide a light fraction 31 havinga 95% boiling point temperature in the range from about 160° C. to about490° C., and to provide the ULSFO stream 30 having a correspondinginitial boiling point or 5% boiling point temperature, such as 490° C.+hydrocarbons.

The light fraction 31 may be fed to a second conditioning section 32 toproduce a highly paraffinic stream 16 suitable for processing in thesteam cracking section 7 for producing chemical streams 23, such asethylene, propylene, and butenes, among others, as well as a higherboiling pyrolysis oil fraction 25. The first conditioning section 27 andthe second conditioning section 32 may be the same or different, and mayinclude one or more hydrotreating and/or hydrocracking reactors.

In some embodiments, conditioning reactors 27 include hydrotreatingcatalysts (first stage conditioning), while conditioning reactors 32include hydrocracking catalysts (second stage conditioning). Further, insome embodiments, the first stage conditioning may include a reactorzone containing a residue desulfurization catalyst. Further, the firststage conditioning may, in some embodiments, include catalysts to targetlowering a content of polynuclear aromatic compounds, therebyconditioning the feed to be more easily processed in the steam cracker.

Referring now to FIG. 4 , a simplified process flow diagram of a systemfor converting whole crudes and heavy hydrocarbons according toembodiments herein is illustrated where like numerals represent likeparts. In this embodiment, the desalted whole crude is processed similarto that as described above for FIG. 3 . A wide boiling range heavyhydrocarbon feed, such as a desalted crude 1, may be fed to a separationsystem 3. Separation system 3 may be an integrated separation device(ISD), as described above and including separation and heat integration,for example. In separation system 3, the desalted crude 1 may beseparated into three fractions, including (a) a 160° C.− fraction 5 thatdoes not require any conditioning and can be used as feed to the steamcracker section 7; (b) a 160-490° C. fraction 9 that may be upgraded ina second conditioning section 32; and (c) a 490° C.+ fraction 15,processed in each of conditioning section 27, ISD 29, and conditioningsection 32, as described above.

In some embodiments, the mid cut (160-490° C.) stream 9 may be processedin a second fixed bed conditioning system 32, separate from stream 31recovered following conditioning and separation of the 490° C.+ stream.

The 490° C.+ stream may be processed in a first fixed bed conditioningsystem 27. The first conditioning system 27 may be designed with one ormore hydrotreating and/or hydrocracking reactors to at least partiallyconvert the 490° C.+ fraction into an ultra-low sulfur fuel oilcontaining stream 28. The first conditioning section 27 and the secondconditioning section 32 may be the same or different, and may includeone or more hydrotreating and/or hydrocracking reactors according to thecomposition of the crude feedstock 1. Stream 28 may then bed fed to asecond separation system 29, such as a second ISD, which may separatethe paraffins and remaining olefins in stream 28 from heavierhydrocarbons. The heavy hydrocarbons may be removed from the separationsystem 29 as an ultra-low sulfur fuel oil (ULSFO) stream 30. Theeffluent 31 which was not removed as ULSFO stream 30, may be combinedwith 160-490° C. fraction 9, forming a combined hydrocarbon stream 33,and may be upgraded in the second conditioning section 32 that maycontain a catalyst tailored to effectively condition the combinedhydrocarbon stream 33. The reaction products 18 from the fixed bedconditioning system 32 may then be co-processed in steam cracker section7 for conversion into light olefins and other valuable chemicals.

As described above, the fixed bed conditioning system 27 may be used tocondition the 490° C.+ fraction 15 separately from the 160-490° C. midcut stream 9, while the second fixed bed conditioning system 32 may beused to condition a combined 160-490° C. mid cut and a partiallyconditioned and separated 490° C.+ fraction. In some embodiments, thestreams may be processed in similar hydrotreating and/or hydrocrackingreactors in each of the first and second conditioning systems 27, 32, orthe hydrotreating and/or hydrocracking reactors may be different.However, it has been found that, due to the nature of the feed compoundsfor various crudes, processing in a single reaction train may result ina stream with molecules that contain more aromatic rings than themolecules in straight run Arab Light or Arab Extra Light crudes in thesame boiling range. As a result, more severe hydrotreating conditionsmay be necessary to sufficiently saturate the molecules, which has anegative impact on hydrotreating catalyst life and/or capitalinvestment. If the 490° C.+ fraction 15 is co-processed with thestraight run 160-490° C. fraction 9 in the first conditioning system 27,the turnaround time for a single hydrotreating train may dropundesireably, and/or a spare hydrotreating train would be required toprovide a steady stream of feed to the steam cracking section while thehydrotreating catalyst system is undergoing regeneration and/orreplacement. The aforementioned would also be applicable to other typesof crude, such as desalted oils, condensate, biogenic oil, synthesiscrude, tight oil, heavy hydrocarbons, reconstituted crudes, and bitumenderived oils.

To alleviate the issues of catalyst life/turnaround time, the fixed bedhydrotreating step may be split, as illustrated in FIG. 4 . The firstconditioning system 27 and second separation system 29 may be providedto initially process and remove at least some of the undesirable heavyhydrocarbons containing metals, asphaltenes, and Conradson CarbonResidue (CCR). The second conditioning system 32 may then be providedfor processing the straight run 160-490° C. crude oil and remaining 490°C.+ fraction. Generally, the reactors in the first conditioning systemmay have less frequent turnaround time than that of reactors in thesecond conditioning system which may have more frequent turnarounds toreplace catalyst, but the straight run 160-490° C. and 490° C.+ fractioncould be combined to either the first conditioning system (27) or thesecond conditioning system (29), during catalyst replacement, so as tonot require a spare reactor train for uptime. As a temporary diversionof feed, the impact on either reactor train would be minimal, and thusconditioning systems could be designed to hydrotreat and/or hydrocrackboth the 160-490° C. and 490° C.+ fraction such that process downtimeduring turnarounds in either the first or second conditioning systemsmay be reduced. Further, the turnaround time for the first conditioningsystem may be in sync with that of the steam cracker furnaces.

As noted above, various feedstocks may allow the cut points to beincreased, such as raising the mid/high cut point from 490° C. to 545°C. in some embodiments. The same may be true with respect to processingin the solvent deasphalting system, where higher boiling pointhydrocarbons may be recovered with the deasphalted oil and fed to thehydrotreating reactor for conversion into feedstocks suitable for steamcracking. However, with respect to processing of the high boilingfraction (e.g., 490° C.+ or 545° C.+ fraction) in the solventdeasphalting system, it has been found that a lower cut point may bemore favorable, as a cut point that is too high may require the use of acutter oil to produce the ULSFO.

Other low value refinery streams may also be processed according toembodiments herein to produce ultimately higher value products. Suchstreams include some or all of the following types of hydrocarbons: (i)Light cycle oil (LCO), such as LCO that is produced from FCC unit, whichcan be processed with the 160-490° C. fraction; (ii) a Slurry Oil, suchas a slurry oil that is produced from an FCC unit, which can beprocessed with the 490° C.+ hydrocarbons; (iii) pitch, such as a pitchthat is produced from a solvent deasphalting unit, which can beprocessed in the first conditioning system with the 490° C.+hydrocarbons; and/or (iv) a Pyrolysis fuel oil (Pyoil), such as apyrolysis fuel oil that is produced from a stream cracker, includingpyrolysis fuel oil stream 25 from steam cracker 7, which stream can beprocessed with the 490° C.+ hydrocarbons. Other various hydrocarbonstreams of similar boiling ranges may also be co-processed to producepetrochemicals in systems disclosed herein, where such streams mayinclude light naphthas, heavy naphthas, crude oils, atmosphericresidues, vacuum residues, synthetic crude oils, and other hydrocarbonstreams containing heavy hydrocarbons. The cut points may also be variedin any of the ISDs to account for varying feedstock quality (i.e.,metals, asphaltenes, and CCRs). In embodiments where the desalted crudehas low contaminants, the initial cut points may be higher (i.e., above160° C.), thereby reducing the operational load on the catalysts in theone or more condition systems. Alternatively, in embodiments where thedesalted crude is high in contaminants, the initial cut points may belower (i.e., below 160° C.), thereby feeding more of the hydrocarbonsthrough a plurality of conditions systems and a second ISD forhydrotreatment and/or removal of undesirable heavy components, andthereby increasing the amount of naphtha range hydrocarbons being fed tosteam cracking.

As described briefly above, embodiments herein may allow for the directcracking of crude oil to chemicals, forming light hydrocarbons likeethylene and propylene, in an economically viable manner, withoutpassing through the conventional refining steps. Additionally, directconversion of crude oil to chemicals may help close the wideningsupply-demand gap for key building blocks normally produced asco-products (propylene, butadiene) due to the increasing shift towardcracking lighter feedstock spurred by the shale gas revolution.

Integration of processing units according to embodiments herein mayprovide the unique potential for upgrading whole crudes, such as ArabLight crude and Arab Extra Light crude, along with low value refinerystreams, such as Pyrolysis Oil (PyOil), slurry oil and Light Cycle Oil(LCO), into higher value chemical products. While conditioning of thefeeds according to embodiments herein adds hydrogen to the feedcomponents, and the hydrogen consumption is an added expense to theplant, the overall benefits in producing chemicals, rather than fuels,outweighs this added expense. The aforementioned would also beapplicable to other types of crude, such as desalted oils, condensate,biogenic oil, synthesis crude, tight oil, heavy hydrocarbons,reconstituted crudes, and bitumen derived oils.

In other embodiments, an optional aromatics complex may be included. Forexample, an aromatics complex may be used to convert the 160° C.-490° C.fraction, or a portion thereof, to aromatics. For example, a mid-cutsuch as 160° C. to 240° C. fraction may be processed to convert aportion of the hydrocarbons therein to aromatics, while the heavies maybe fed to the steam cracker for conversion to chemicals. The aromaticscomplex feedstock generated via initial processing and conditioningaccording to embodiments herein may permit various processors todiscontinue importing full range naphtha (FRN).

Further, in some embodiments, the pyrolysis oil generated in the steamcracking unit may be separated to recover a pyrolysis gasoline fraction,and one or more heavies fractions, such as a pyrolysis gas oil fractionand a pyrolysis fuel oil fraction. The lighter pyrolysis gasolinefaction may be fed to an aromatics unit, while the heavier fractions maybe used to form an ULSFO, as noted above.

As described with respect to FIGS. 2-4 , separation systems 3 or (3+29)may be as illustrated in FIG. 5 , including separation and heatintegration. After desalting, the crude 1 may be further preheated inthe convection section of a heater 500 to produce a preheated crude 502.The preheated crude 502 may be fed to a separator 504 which mayfacilitate the separation of the 160° C.− fraction 5 from heaviercomponents, recovered in stream 506.

The remaining 160° C.+ crude fraction 506 may be fed to a pump 508,which produces a pressurized 160° C.+ crude fraction 510, which may thenbe fed to a heat exchanger 512. ISD heat exchanger 512 may preheat the160° C.+ crude fraction 510 against hot hydrogen stripper bottoms 520,producing a pressurized and pre-heated 160° C.+ crude fraction 514. Thepressurized and pre-heated 160° C.+ crude fraction 514 may then be fedback to the heater 500, where it is heated to facilitate the separationof a 160-490° C. fraction from a heavier 490° C.+ fraction. The heated160° C.+ crude fraction 516 may then be fed to a hot hydrogen stripper518. In the hot hydrogen stripper 518, the 160° C.+ crude fraction isfurther separated into a 160-490° C. fraction 9 and the hot hydrogenstripper bottoms 520, which contains heavier 490° C.+ hydrocarbons. Thehot hydrogen stripper bottoms 520, after being cooled via indirect heatexchange in heat exchanger 512 against the pressurized 160° C.+ crudefraction 510, may be removed from the separation system 3 as the 490°C.+ fraction 15.

The hot hydrogen stripper 518 may utilize a hydrogen feed 522 as thestripping medium. The hot hydrogen stripper 518 may be operated toprovide broad flexibility, based on the nature of the crude feedstockthat is being processed. The stripper overheads, which is the 160-490°C. fraction 9, may be cooled, to recover hydrogen, and routed to theintermediate hydroprocessing reaction stages as appropriate, and asdescribed with respect with FIG. 4 . The recovered hydrogen may be fedto a downstream pressure swing adsorption (PSA) unit (not shown), afteramine treatment (not shown), to improve the hydrogen purity. The PSAhydrogen product may be compressed in a make-up hydrogen compressor (notshown) to provide the make-up hydrogen for the one or morehydroprocessing reactors (FIG. 4 ), and as hot hydrogen feed 522.

The hot hydrogen stripper bottoms product 520 (such as a 490° C.+ cut)contains the most difficult compounds which must be handled in thecrude, including asphaltenes, metals, and CCR. The excessive amount ofmetals, CCR, and asphaltenes in the high boiling residue fraction leadsto rapid fouling of catalyst and increase of pressure drop in fixed beddown-flow reactors, limiting both conversion and catalyst run length.After cooling against the pressurized 160° C.+ crude fraction 510, the490° C.+ stream 15 may be recovered and processed in a liquidcirculation, ebullated bed residue hydrocracker, as described in FIG. 4, along with any additional low value refinery streams, such as a pyoilstream and/or slurry oil stream.

By adjusting the amount of hydrogen 522 fed to the hot hydrogen stripper518, as well as the operating conditions of the hot hydrogen stripper518 and heater 500, the hydrocarbon cut points may be adjusted such thatthe light-cut 5 may be fed directly to the downstream steam cracker, andthe mid-cut 9 may have little to no deleterious compounds that wouldrapidly foul the fixed bed conditioning reactors. In this way, theseparation system 3 (with the hot hydrogen stripper 518) may concentratethe most difficult to process hydrocarbons in the heavy-cut 15 which maybe fed to the ebullated bed reactors which may be operated at the mostsevere conditions, thereby preserving the catalysts in the steam crackerand fix bed conditioning reactors.

Embodiments herein provide a strategic combination of crude feedpreparation, crude separation, crude conditioning, and steam crackingtechnology to maximize the yield of high value chemicals. The crudeconditioning section employs a combination of fixed bed hydroprocessingand liquid circulation to condition the crude into a suitable steamcracker feed and to upgrade the low value refinery streams. Embodimentsherein may achieve a yield of petrochemicals or chemicals in the rangeof 60% to 90% of the whole crude feedstock, for example.

After desalting, the crude may be segregated into three cuts, including:a 160° C.− stream; a 160-490° C. stream; and a 490° C.+ stream. The 160°C.− stream does not require upgrading, and thus can be directly routedas steam cracker. The 160-490° C. stream is easily handled in a fixedbed hydroprocessing reaction system, in which the feed is hydrotreatedand converted to naphtha, making an ideal steam cracker feedstock.

Embodiments herein may employ one or more hydrotreating and/orhydrocracking reactions, and an integrated separation device, to removethe pitch (asphaltenes) and metals, thereby increasing the runtime ofthe conversion process without fouling the reactors. In someembodiments, the pitch, asphaltenes, and metals may be fed to a delayedcoking unit to recover the carbon that is contained in these streams.

Embodiments herein may provide upstream processing to process wholecrude and other wide boiling range hydrocarbons in a steam cracker,where embodiments of the overall integrated processes may be configuredto have a common run time. This may be done by having fail-over, orcut-over, from one conditioning system to the other in order to minimizetotal system downtime during catalyst regeneration, maintenance, orcleaning. Further, such embodiments may eliminate the need for parallelreaction trains or redundant process units, in both the mid-rangehydrocarbon processing and the high boiling residue processing, for useduring catalyst regeneration.

Further, the hydrotreating and hydrocracking reactors in each of thefirst and second conditioning systems may be sized to have run-timessimilar to the steam cracking unit. Such configurations may additionallyallow for reduced down-time as cleaning, maintenance, and catalystregeneration may be accomplished all at once across multiple reactionsystems. Without such design considerations, operations may haveincreased downtime while reactors in the first conditioning system, forexample, are taken offline for catalyst regeneration while the catalystsin the second conditioning system still have >50% catalyst life.

Additionally, avoiding entrainment of heavy materials in the front endseparations may lower costs, and may result in less complex flow schemesas illustrated and described herein. Further, the avoidance ofentrainment may ensure the operability and processability in the crudeconditioning systems and steam cracker, allowing for lower overallcapital expense while achieving a high yield of chemicals.

As described above, embodiments herein may separate a desalted crude orother wide boiling hydrocarbons into various fractions to effectivelycondition the respective fractions to form a feedstock suitable forconversion in a steam cracker. Because of the wide range of feedstocksthat may be processed according to embodiments herein, depending uponthe feedstock, conditioning catalysts, reactor volumes, and otherfactors for a given installation, it may be more preferential to basethe specific cut points based on one or more additional properties ofthe feedstock. For example, the specific cut points may be adjustedbased on one or more properties or additional properties of the crudefeedstock, such as API gravity, Bureau of Mines Correlation Index(BMCI), hydrogen content, nitrogen content, sulfur content, viscosity,microcarbon residue (MCRT), and/or total metals, among other feedstockproperties.

Various feedstocks useful in embodiments herein, such as crude oils,desalted oils, condensate, biogenic oil, synthetic crude, tight oil,heavy hydrocarbons, reconstituted crude and bitumen derived oil may haveone or more of the following properties, including: an API gravitybetween 4 and 60°, a BMCI of 20 to 85, a hydrogen content of 9.0 to 14.5wt % (or 90,000 to 145,000 ppm), a nitrogen content of 0.02 to 0.95 wt %(or 200 to 9,500 ppm), a sulfur content of 0.009 to 6.0 wt % (or 90 to60,000 ppm), a viscosity, at 40° C., of 95 to 5500 centistokes (cSt), aMCRT of 5 to 35 wt %, and/or may have a total metals content of <1 to1000 ppm.

The initial crude separations may be conducted and adjusted in order tohave the light- and heavy-cuts, or the light-, mid-, and heavy-cuts havespecific properties, such that the light-cut may go to the steam crackerwith no, or minimal, intermediate processing. Further, the mid to heavycuts may be conducted and adjusted in order to have the mid-cut and/orheavy-cut have appropriate and/or favorable feed properties andhydrocarbon species so as to be effectively and efficiently conditionedin the mid and heavy conditioning reactors.

BMCI

In some embodiments, the light cut may have a BMCI of less than 20. Inother embodiments, the light cut may have a BMCI of less than 15. In yetother embodiments, the light cut may have a BMCI of less than 10 or evenless than 5. In some embodiments, the mid cut may have a BMCI of lessthan 40, such as less than 35, less than 30, or less than 25. In someembodiments, the heavy cut may have a BMCI of greater than 30, such asgreater than 35, greater than 40, greater than 45, greater than 50, orgreater than 55.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 90° C. to about 300° C., for example,may have a BMCI of less than 20; in other embodiments, such as when thelight cut includes hydrocarbons having a boiling point up to about 110°C. or up to about 250° C., for example, the light cut may have a BMCI ofless than 10; in yet other embodiments, such as when the light cutincludes hydrocarbons having a boiling point up to about 130° C. or upto about 220° C., for example, the light cut may have a BMCI of lessthan 5. In some embodiments where the light cut includes hydrocarbonshaving a boiling point below about 160° C., the light cut may have aBMCI of less than 5. While the BMCI may vary for the different feeds atany given cut temperature, a low BMCI, such as less than 10 or less than5, for example, has been found to improve the processability of thelight hydrocarbons in the steam pyrolysis unit without the need forintermediate processing. Light cuts for Arab light crudes processedaccording to embodiments herein may target a BMCI of less than 10, forexample, and may target a BMCI of less than 6 or less than 5.5 for Arabextra light crudes, for example.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a BMCI of between about 5 and 50. For example, the mid cut mayhave a BMCI of between a lower limit of 5, 10, 15, 20, or 25 to an upperlimit of 10, 15, 20, 25, 30, 40, or 50. A mid-cut having a BMCI ofbetween 10 and 30, for example, has been found to be convertible tosteam cracker feeds using relatively moderate destructive hydrogenationconditions in the mid-cut conditioning section of processes herein.Mid-cuts for Arab light crudes processed according to embodiments hereinmay target a BMCI in the range from about 20 to about 30, for example,and may target a BMCI in the range from about 15 to about 30 for Arabextra light crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a BMCI of greaterthan 30. When the heavy cut includes hydrocarbons having a boiling pointabove about 350° C., the heavy cut may have a BMCI of greater than 40.When the heavy cut includes hydrocarbons having a boiling point aboveabout 400° C., the heavy cut may have a BMCI of greater than 50. Inembodiments where the heavy cut includes hydrocarbons having a boilingpoint above about 490° C., the heavy cut may have a BMCI of greater than55. A heavy-cut having a BMCI of greater than about 40, for example, hasbeen found to be convertible to steam cracker feeds using the moresevere destructive hydrogenation conditions in the heavy-cutconditioning section of processes herein. Heavy-cuts for Arab lightcrudes processed according to embodiments herein may target a BMCI inthe range from about 50 to about 60, for example, and may target a BMCIin the range from about 25 to about 40 for Arab extra light crudes, forexample.

API

In some embodiments, the light cut may have an API gravity of greaterthan 10°. In other embodiments, the light cut may have an API gravity ofgreater than 15°. In yet other embodiments, the light cut may have anAPI gravity of greater than 20°, greater than 30°, or even greater than40°. In some embodiments, the mid cut may have an API gravity of greaterthan 10° and less than 40°, such as from a lower limit of 10°, 15°, 20°,25°, or 30° to an upper limit of 25°, 30°, 35°, 40°, 45°, or 50°. Insome embodiments, the heavy cut may have an API gravity of less than40°, such as less than 35°, less than 25°, less than 20°, less than 15°,or less than 10°.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 300° C., for example, may have an APIgravity of greater than 10°; in other embodiments, such as when thelight cut includes hydrocarbons having a boiling point up to about 250°C., for example, the light cut may have an API gravity of greater than20°; in yet other embodiments, such as when the light cut includeshydrocarbons having a boiling point up to about 220° C., for example,the light cut may have an API gravity of greater than 40°. In someembodiments where the light cut includes hydrocarbons having a boilingpoint below about 160° C., the light cut may have an API gravity ofgreater than 60°. While the API gravity may vary for the different feedsat any given cut temperature, an API gravity, such as greater than 40°,greater than 50°, or greater than 60°, for example, has been found toimprove the processability of the light hydrocarbons in the steampyrolysis unit without the need for intermediate processing. Light cutsfor Arab light crudes processed according to embodiments herein maytarget an API gravity of greater than 65°, for example, and may targetan API gravity of greater than 60° for Arab extra light crudes, forexample.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have an API gravity of between about 5° and 50°. For example, themid cut may have an API gravity of between a lower limit of 5°, 10°,15°, 20°, or 25° to an upper limit of 10°, 15°, 20°, 25°, 30°, 40°, or50°. A mid-cut having an API gravity of between 20° and 40°, forexample, has been found to be convertible to steam cracker feeds usingrelatively moderate destructive hydrogenation conditions in the mid-cutconditioning section of processes herein. Mid-cuts for Arab light crudesprocessed according to embodiments herein may target an API gravity inthe range from about 30° to about 35°, for example, and may target anAPI gravity in the range from about 35° to about 40° for Arab extralight crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have an API gravity ofless than about 40°. When the heavy cut includes hydrocarbons having aboiling point above about 350° C., the heavy cut may have an API gravityof less than about 20°. When the heavy cut includes hydrocarbons havinga boiling point above about 400° C., the heavy cut may have an APIgravity of less than about 10°. In embodiments where the heavy cutincludes hydrocarbons having a boiling point above about 490° C., theheavy cut may have an API gravity of less than 7°, for example. Aheavy-cut having an API gravity of less than about 20°, for example, hasbeen found to be convertible to steam cracker feeds using the moresevere destructive hydrogenation conditions in the heavy-cutconditioning section of processes herein. Heavy-cuts for Arab lightcrudes processed according to embodiments herein may target an APIgravity in the range from about 5° to about 10°, for example, and maytarget an API gravity in the range from about 10° to about 20° for Arabextra light crudes, for example.

Hydrogen Content

In some embodiments, the light cut may have a hydrogen content ofgreater than 12 wt %. In other embodiments, the light cut may have ahydrogen content of greater than 13 wt %. In yet other embodiments, thelight cut may have a hydrogen content of greater than 13.5 wt %, greaterthan 14 wt %, or even greater than 15 wt %. In some embodiments, the midcut may have a hydrogen content of greater than 11 wt % and less than 14wt %, such as from a lower limit of 11, 11.5, 12.0, 12.5, or 13.0 wt %to an upper limit of 12.0, 12.5, 13.0, 13.5, 14.0, or 14.5 wt %. In someembodiments, the heavy cut may have a hydrogen content of less than 13wt %, such as less than 12.5 wt %, less than 12 wt %, less than 11.5 wt%, or less than 11 wt %.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 300° C., for example, may have anhydrogen content of greater than 13 wt %; in other embodiments, such aswhen the light cut includes hydrocarbons having a boiling point up toabout 250° C., for example, the light cut may have an hydrogen contentof greater than 13.5 wt %; in yet other embodiments, such as when thelight cut includes hydrocarbons having a boiling point up to about 220°C., for example, the light cut may have an hydrogen content of greaterthan 14.0 wt %. In some embodiments where the light cut includeshydrocarbons having a boiling point below about 160° C., the light cutmay have a hydrogen content of greater than 14.5 wt %. While thehydrogen content may vary for the different feeds at any given cuttemperature, a hydrogen content, such as greater than 13 wt %, greaterthan 14 wt %, or greater than 14.5 wt %, for example, has been found toimprove the processability of the light hydrocarbons in the steampyrolysis unit without the need for intermediate processing. Light cutsfor Arab light crudes processed according to embodiments herein maytarget a hydrogen content of greater than 14.5 wt %, for example, andmay target a hydrogen content of greater than 14 wt % for Arab extralight crudes, for example.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a hydrogen content of between about 11.5 wt % and 14.5 wt %. Amid-cut having a hydrogen content of between 12 wt % and 13.5 wt %, forexample, has been found to be convertible to steam cracker feeds usingrelatively moderate destructive hydrogenation conditions in the mid-cutconditioning section of processes herein. Mid-cuts for Arab light crudesprocessed according to embodiments herein may target a hydrogen contentin the range from about 12.5 wt % to about 13.5 wt %, for example, andmay target an hydrogen content in the range from about 13.0 wt % toabout 14.0 wt % for Arab extra light crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a hydrogen content ofless than about 13 wt %. When the heavy cut includes hydrocarbons havinga boiling point above about 350° C., the heavy cut may have a hydrogencontent of less than about 12.5 wt %. When the heavy cut includeshydrocarbons having a boiling point above about 400° C., the heavy cutmay have a hydrogen content of less than about 12.0 wt %. In embodimentswhere the heavy cut includes hydrocarbons having a boiling point aboveabout 490° C., the heavy cut may have a hydrogen content of less than 11wt %, for example. A heavy-cut having a hydrogen content of less thanabout 12 wt %, for example, has been found to be convertible to steamcracker feeds using the more severe destructive hydrogenation conditionsin the heavy-cut conditioning section of processes herein. Heavy-cutsfor Arab light crudes processed according to embodiments herein maytarget a hydrogen content in the range from about 10 wt % to about 11 wt%, for example, and may target a hydrogen content in the range fromabout 11 wt % to about 12 wt % for Arab extra light crudes, for example.

Nitrogen Content

In some embodiments, the light cut may have a nitrogen content of lessthan 100 ppm, such as less than 50 ppm or less than 30 ppm. In otherembodiments, the light cut may have a nitrogen content of less than 25ppm. In yet other embodiments, the light cut may have a nitrogen contentof less than 20 ppm, less than 15 ppm, less than 10 ppm, less than 5ppm, less than 3 ppm, less than 1 ppm, or even less than 0.5 ppm. Insome embodiments, the mid cut may have a nitrogen content of greaterthan 1 ppm and less than 1000 ppm, such as from a lower limit of 1, 5,10, 50, 100, 250, or 500 ppm to an upper limit of 50, 100, 250, 500, or1000 ppm. In some embodiments, the heavy cut may have a nitrogen contentof greater than 10 ppm, such as greater than 25 ppm, greater than 50ppm, greater than 100 ppm, greater than 150 ppm, greater than 200 ppm,greater than 250 ppm, greater than 500 ppm, greater than 1000 ppm,greater than 1500 ppm, greater than 2000 ppm, or greater than 2500 ppm.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 300° C., for example, may have annitrogen content of less than 0.01 wt %, or 100 ppm; in otherembodiments, such as when the light cut includes hydrocarbons having aboiling point up to about 250° C., for example, the light cut may havean nitrogen content of less than 0.001 wt %, or 10 ppm; in yet otherembodiments, such as when the light cut includes hydrocarbons having aboiling point up to about 220° C., for example, the light cut may have anitrogen content of less than 0.0001 wt %, or 1 ppm. In some embodimentswhere the light cut includes hydrocarbons having a boiling point belowabout 160° C., the light cut may have a nitrogen content of less thanabout 0.00003 wt %, or 0.3 ppm. While the nitrogen content may vary forthe different feeds at any given cut temperature, a nitrogen content,such as less than about 100 ppm, less than 10 ppm, or less than 1 ppm,for example, has been found to improve the convertibility of the lighthydrocarbons in the steam pyrolysis unit without the need forintermediate processing. Light cuts for Arab light crudes processedaccording to embodiments herein may target a nitrogen content of lessthan 1 ppm, for example, and may also target a nitrogen content of lessthan 1 ppm for Arab extra light crudes, for example.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a nitrogen content of between about 10 ppm and 250 ppm, forexample. A mid-cut having a nitrogen content of between 20 and 250 ppm,for example, has been found to be convertible to steam cracker feedsusing relatively moderate destructive hydrogenation conditions in themid-cut conditioning section of processes herein. Mid-cuts for Arablight crudes processed according to embodiments herein may target anitrogen content in the range from about 200 to about 300 ppm, forexample, and may target an nitrogen content in the range from about 100to about 150 ppm for Arab extra light crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a nitrogen content ofgreater than about 0.001 wt %, or 10 ppm. When the heavy cut includeshydrocarbons having a boiling point above about 350° C., the heavy cutmay have a nitrogen content of greater than about 0.005 wt %, or 50 ppm.When the heavy cut includes hydrocarbons having a boiling point aboveabout 400° C., the heavy cut may have a nitrogen content of greater thanabout 0.01 wt %, or 100 ppm. In embodiments where the heavy cut includeshydrocarbons having a boiling point above about 490° C., the heavy cutmay have a nitrogen content of greater than 2500 ppm, for example. Aheavy-cut having a nitrogen content of greater than about 100 ppm, forexample, has been found to be convertible to steam cracker feeds usingthe more severe destructive hydrogenation conditions in the heavy-cutconditioning section of processes herein. Heavy-cuts for Arab lightcrudes processed according to embodiments herein may target a nitrogencontent in the range from about 2000 to about 3000 ppm, for example, andmay target a nitrogen content in the range from about 1000 to about 2000for Arab extra light crudes, for example.

Sulfur Content

In some embodiments, the light cut may have a sulfur content of lessthan 10000 ppm, such as less than 5000 ppm or less than 1000 ppm. Inother embodiments, the light cut may have a sulfur content of less than750 ppm. In yet other embodiments, the light cut may have a sulfurcontent of less than 500 ppm, less than 250 ppm, or even less than 100ppm. In some embodiments, the mid cut may have a sulfur content ofgreater than 500 ppm and less than 10000 ppm, such as from a lower limitof 500, 750, 1000, 1500, 2000, 2500, or 5000 ppm to an upper limit of1000, 2000, 5000, 10000, 15000, or 20000 ppm. In some embodiments, theheavy cut may have a sulfur content of greater than 1000 ppm, such asgreater than 2500 ppm, greater than 5000 ppm, greater than 10000 ppm,greater than 15000 ppm, greater than 20000 ppm, greater than 25000 ppm,greater than 30000 ppm, greater than 35000 ppm, greater than 40000 ppm,greater than 45000 ppm, or greater than 50000 ppm.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 300° C., for example, may have ansulfur content of 1 wt %, or 10,000 ppm; in other embodiments, such aswhen the light cut includes hydrocarbons having a boiling point up toabout 250° C., for example, the light cut may have an sulfur content ofless than 0.5 wt %, or 5,000 ppm; in yet other embodiments, such as whenthe light cut includes hydrocarbons having a boiling point up to about220° C., for example, the light cut may have a sulfur content of lessthan 0.1 wt %, or 1,000 ppm. In some embodiments where the light cutincludes hydrocarbons having a boiling point below about 160° C., thelight cut may have a sulfur content of less than about 750 ppm or lessthan 500 ppm. While the sulfur content may vary for the different feedsat any given cut temperature, a sulfur content, such as less than about600 ppm, for example, has been found to improve the convertibility ofthe light hydrocarbons in the steam pyrolysis unit without the need forintermediate processing. Light cuts for Arab light crudes processedaccording to embodiments herein may target a sulfur content of less than750 ppm, for example, and may also target a sulfur content of less than500 ppm for Arab extra light crudes, for example.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a sulfur content of between about 1000 ppm and 20000 ppm, forexample. A mid-cut having a sulfur content of between 2000 and 15000ppm, for example, has been found to be convertible to steam crackerfeeds using relatively moderate destructive hydrogenation conditions inthe mid-cut conditioning section of processes herein. Mid-cuts for Arablight crudes processed according to embodiments herein may target asulfur content in the range from about 6000 to about 12000 ppm, forexample, and may target an sulfur content in the range from about 5000to about 10000 ppm for Arab extra light crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a sulfur content ofgreater than about 0.1 wt %, or 1,000 ppm. When the heavy cut includeshydrocarbons having a boiling point above about 350° C., the heavy cutmay have a sulfur content of greater than about 0.5 wt %, or 5,000 ppm.When the heavy cut includes hydrocarbons having a boiling point aboveabout 400° C., the heavy cut may have a sulfur content of greater thanabout 1 wt %, or 1,0000 ppm. In embodiments where the heavy cut includeshydrocarbons having a boiling point above about 490° C., the heavy cutmay have a sulfur content of greater than 25000 ppm, for example. Aheavy-cut having a sulfur content of greater than about 10000 ppm, forexample, has been found to be convertible to steam cracker feeds usingthe more severe destructive hydrogenation conditions in the heavy-cutconditioning section of processes herein. Heavy-cuts for Arab lightcrudes processed according to embodiments herein may target a sulfurcontent in the range from about 30000 to about 50000 ppm, for example,and may target a sulfur content in the range from about 20000 to about30000 for Arab extra light crudes, for example.

Viscosity

In some embodiments, the light cut may have a viscosity, measured at 40°C. according to ASTM D445, of less than 10 cSt. In other embodiments,the light cut may have a viscosity, measured at 40° C., of less than 5cSt. In yet other embodiments, the light cut may have a viscosity,measured at 40° C., of less than 1 cSt. In some embodiments, the heavycut may have a viscosity, measured at 100° C. according to ASTM D445, ofgreater than 10 cSt, such as greater than 20 cSt, greater than 35 cSt,greater than 50 cSt, greater than 75 cSt, or greater than 100 cSt. Invarious embodiments, the mid-cut may have a viscosity intermediate thatof the light and heavy cuts.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 300° C., for example, may have aviscosity, measured at 40° C., of less than 10 cSt; in otherembodiments, such as when the light cut includes hydrocarbons having aboiling point up to about 250° C., for example, the light cut may have aviscosity, measured at 40° C., of less than 5 cSt; in yet otherembodiments, such as when the light cut includes hydrocarbons having aboiling point up to about 220° C., for example, the light cut may have aviscosity, measured at 40° C., of less than 1 cSt. In some embodimentswhere the light cut includes hydrocarbons having a boiling point belowabout 160° C., the light cut may have a viscosity, measured at 40° C.,of less than 0.75 cSt. While the viscosity may vary for the differentfeeds at any given cut temperature, a low viscosity, such as less than10 cSt, for example, has been found to improve the processability of thelight hydrocarbons in the steam pyrolysis unit without the need forintermediate processing. Light cuts for Arab light crudes processedaccording to embodiments herein may target a viscosity of less than 0.55cSt, for example, and may target a viscosity of less than 0.6 cSt forArab extra light crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a viscosity, measuredat 100° C., of greater than 10 cSt. When the heavy cut includeshydrocarbons having a boiling point above about 350° C., the heavy cutmay have a viscosity, measured at 100° C., of greater than 50 cSt. Whenthe heavy cut includes hydrocarbons having a boiling point above about400° C., the heavy cut may have a viscosity, measured at 100° C., ofgreater than 100 cSt. In embodiments where the heavy cut includeshydrocarbons having a boiling point above about 490° C., the heavy cutmay have a viscosity of greater than 375 cSt, for example. A heavy-cuthaving a viscosity of greater than about 40 cSt, for example, has beenfound to be convertible to steam cracker feeds using the more severedestructive hydrogenation conditions in the heavy-cut conditioningsection of processes herein.

MCRT

In some embodiments, the light cut may have only trace amounts, orundetectable amounts, of microcarbon residue (MCRT). In someembodiments, the mid cut may have a MCRT of less than 5 wt %, such asless than 3 wt %, less than 1 wt %, or less than 0.5 wt %. In someembodiments, the heavy cut may have an MCRT of greater than 0.5 wt %,such as greater than 1 wt %, greater than 3 wt %, greater than 5 wt %,or greater than 10 wt %.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a MCRT of between about 0 wt % (trace or unmeasurable) and 1 wt%. A mid-cut having negligible MCRT, for example, has been found to beconvertible to steam cracker feeds using relatively moderate destructivehydrogenation conditions in the mid-cut conditioning section ofprocesses herein.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a MCRT of greaterthan 0.5 wt %. When the heavy cut includes hydrocarbons having a boilingpoint above about 350° C., the heavy cut may have a MCRT of greater than1 wt %. When the heavy cut includes hydrocarbons having a boiling pointabove about 400° C., the heavy cut may have a MCRT of greater than 5 wt%. In embodiments where the heavy cut includes hydrocarbons having aboiling point above about 490° C., the heavy cut may have a MCRT ofgreater than 15 wt %, for example. A heavy-cut having a MCCRT of greaterthan about 1 wt %, for example, has been found to be convertible tosteam cracker feeds using the more severe destructive hydrogenationconditions in the heavy-cut conditioning section of processes herein.

Metals Content

In some embodiments, the light cut may have only trace amounts, orundetectable amounts, of metals. In some embodiments, the mid cut mayhave a metals content of up to 50 ppm, such as less than 30 ppm, lessthan 10 ppm, or less than 1 ppm. In some embodiments, the heavy cut mayhave a metals content of greater than 1 ppm, such as greater than 10ppm, greater than 20 ppm, greater than 35 ppm, or greater than 50 ppm.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a metals content of between about 0 ppm (trace or unmeasurable)and 5 ppm, such as from greater than 0 ppm to 1 ppm. A mid-cut havingnegligible metals content, for example, has been found to be convertibleto steam cracker feeds using relatively moderate destructivehydrogenation conditions in the mid-cut conditioning section ofprocesses herein.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a metals content ofgreater than 1 ppm. When the heavy cut includes hydrocarbons having aboiling point above about 350° C., the heavy cut may have a metalscontent of greater than 10 ppm. When the heavy cut includes hydrocarbonshaving a boiling point above about 400° C., the heavy cut may have ametals content of greater than 50 ppm. In embodiments where the heavycut includes hydrocarbons having a boiling point above about 490° C.,the heavy cut may have a metals content of greater than 75 ppm, forexample. A heavy-cut having a metals content of greater than about 10ppm, for example, has been found to be convertible to steam crackerfeeds using the more severe destructive hydrogenation conditions in theheavy-cut conditioning section of processes herein.

As an example, an Arab Light crude oil stream may be separated in theinitial separation step in order to produce the desired light-, mid-,and heavy-cuts. Without intending to be bound by theory, the light-cutmay be a 160° C.− fraction with 5% of the fraction having a boilingpoint below 36° C. and 95% of the fraction having a boiling point below160° C. (only 5% of the fraction would have a boiling point above 160°C.). The light cut may have an API gravity of about 65.5°, may have aBMCI of about 5.2, may have a hydrogen content of about 14.8 wt % (or148,000 ppm), may have a nitrogen content of less than 0.00003 wt % (or0.3 ppm), may have a sulfur content of about 0.0582 wt % (or 582 ppm),may have a viscosity, at 40° C., of about 0.5353 centistokes (cSt), andmay have only trace amounts of MCRT and total metals content. Themid-cut may be a 160° C. to 490° C. fraction with 5% of the fractionhaving a boiling point below 173° C. and 95% of the fraction having aboiling point below 474° C. (only 5% of the fraction would have aboiling point above 474° C.). The mid-cut may have an API gravity ofabout 33.6°, may have a BMCI of about 25, may have a hydrogen content ofabout 12.83 wt % (or 128,300 ppm), may have a nitrogen content of lessthan 0.0227 wt % (or 227 ppm), may have a sulfur content of about 0.937wt % (or 9,370 ppm), may have a viscosity, at 100° C., of about 1.58centistokes (cSt), may have an MCRT of 0.03 wt %, and may have onlytrace amounts of total metals content. The heavy-cut may be a 490° C.+fraction with 5% of the fraction having a boiling point below 490° C.and 95% of the fraction having a boiling point below 735° C. (only 5% ofthe fraction would have a boiling point above 735° C.). The heavy-cutmay have an API gravity of about 8.2°, may have a BMCI of about 55, mayhave a hydrogen content of about 10.41 wt % (or 104,100 ppm), may have anitrogen content of less than 0.2638 wt % (or 2,368 ppm), may have asulfur content of about 3.9668 wt % (or 39,668 ppm), may have aviscosity, at 100° C., of about 394.3 centistokes (cSt), may have anMCRT of 17.22 wt %, and may have a total metals content 79.04 ppm.

As another example, an Arab Extra Light crude oil stream may beseparated in the initial separation step in order to produce the desiredlight-, mid-, and heavy-cuts. Without intending to be bound by theory,the light-cut may be a 160° C.− fraction with 5% of the fraction havinga boiling point below 54° C. and 95% of the fraction having a boilingpoint below 160° C. (only 5% of the fraction would have a boiling pointabove 160° C.). The light cut may have an API gravity of about 62°, mayhave a BMCI of about 9.09, may have a hydrogen content of about 14.53 wt% (or 145,300 ppm), may have a nitrogen content of less than 0.00003 wt% (or 0.3 ppm), may have a sulfur content of about 0.0472 wt % (or 472ppm), may have a viscosity, at 40° C., of about 0.58 centistokes (cSt),and may have only trace amounts of MCRT and total metals content. Themid-cut may be a 160° C. to 490° C. fraction with 5% of the fractionhaving a boiling point below 169° C. and 95% of the fraction having aboiling point below 456° C. (only 5% of the fraction would have aboiling point above 474° C.). The mid-cut may have an API gravity ofabout 36.1°, may have a BMCI of about 21.22, may have a hydrogen contentof about 13.38 wt % (or 133,800 ppm), may have a nitrogen content ofless than 0.01322 wt % (or 132.2 ppm), may have a sulfur content ofabout 0.9047 wt % (or 9,047 ppm), may have a viscosity, at 100° C., ofabout 1.39 centistokes (cSt), and may have only trace amounts of MCRTand total metals content. The heavy-cut may be a 490° C.+ fraction with5% of the fraction having a boiling point below 455° C. and 95% of thefraction having a boiling point below 735° C. (only 5% of the fractionwould have a boiling point above 735° C.). The heavy-cut may have an APIgravity of about 15.1°, may have a BMCI of about 33.28, may have ahydrogen content of about 11.45 wt % (or 114,500 ppm), may have anitrogen content of less than 0.1599 wt % (or 1,599 ppm), may have asulfur content of about 2.683 wt % (or 26,830 ppm), may have aviscosity, at 100° C., of about 48.79 centistokes (cSt), may have anMCRT of 9.53 wt %, and may have a total metals content 58.45 ppm.

While the various properties have been described with respect to ArabLight and Arab Extra Light, the aforementioned would also be applicableto other types of crude, such as desalted oils, condensate, biogenicoil, synthesis crude, tight oil, heavy hydrocarbons, reconstitutedcrudes, and bitumen derived oils.

Embodiments herein contemplate adjustment of the various cut points andreactor conditions based upon one or more of the above-noted properties.Methods according to embodiments herein may assay the petroleum feeds tobe used, measuring one or more of the various properties of an incomingfeed. Based on one or more of the properties, cut points, catalyst types(for moving bed reactors), pressures, temperatures, space velocity,hydrogen feed rates, and other variables may be adjusted to moreeffectively and efficiently utilize the reactor configuration, so as tomaintain prime, near optimal, or optimal conditioning of the feedstockand the various cuts to desirable steam cracker feedstocks.

For example, the ebullated bed which receives the heavy-cut may have acapacity to process an amount of hydrocarbon having a sulfur content ofless than 40,000 ppm. If a particular 490° C.+ heavy-cut would have asulfur content of greater than 40,000 ppm, the capacity of the ebullatedbed may be reduced. Accordingly, the heavy-cut point may be reduced, to465° C.+, for example, in order have the sulfur content be less than40,000 ppm. Further, if a particular 160° C.-490° C. mid-cut fractionhas a hydrogen content of greater than 14 wt %, for example, and thenitrogen, sulfur, MCRT, and total metals is suitably low, the light-cutfraction may be expanded (from 160° C.− to 190° C.−, for example) toroute more of the whole crude directly to the steam cracker.Alternatively, if the mid-cut is lower in hydrogen, for example, and/orthe sulfur, nitrogen, MCRT, and/or total metals are not suitably low,the light-cut may be reduced (from 160° C.− to 130° C.−, for example),such that additional mid-cut may be processed in the fixed bedconditioning stages.

As described above, embodiments herein may relate to one or more of thefollowing embodiments:

Embodiment 1: A process for converting whole crudes and other heavyhydrocarbon streams to produce olefins and/or aromatics, the processcomprising:

-   -   feeding a hydrocarbon feedstock into a heater, producing a        pre-heated hydrocarbon feedstock;    -   separating the pre-heated hydrocarbon feedstock in a separator        into a light boiling fraction and an intermediate fraction;    -   feeding the intermediate fraction back to the heater, producing        a heated intermediate fraction;    -   feeding a hydrogen stream to a hot hydrogen stripper;    -   separating the heated intermediate fraction in the hot hydrogen        stripper into a medium boiling fraction and a hot hydrogen        stripper bottoms fraction; and    -   cooling the hot hydrogen stripper bottoms fraction via indirect        heat exchange against the intermediate fraction producing a high        boiling residue fraction;    -   hydrotreating the high boiling residue fraction in a first        hydroprocessing system to produce a hydrotreated effluent;    -   separating the hydrotreated effluent in an integrated separation        device to produce an ultra-low sulfur fuel oil and a        hydroprocessed fraction;    -   hydrocracking the hydroprocessed fraction in a second        hydroprocessing system to produce a steam cracker feedstream;    -   feeding the steam cracker feedstream and the light boiling        fraction to a steam cracker to convert hydrocarbons therein into        one or more light olefins and a pyrolysis oil.

Embodiment 2: The process of embodiment 1, wherein the light boilingfraction has two or more of the following properties:

-   -   a 95% boiling point temperature in the range from about 130° C.        to about 200° C.;    -   a hydrogen content of at least 14 wt %;    -   a BMCI of less than 5;    -   an API gravity of greater than 40°;    -   a sulfur content of less than 1000 ppm;    -   a nitrogen content of less than 10 ppm;    -   a viscosity, measured at 40° C., of less than 1 cSt;    -   less than 1 wt % MCRT; and    -   less than 1 ppm total metals.

Embodiment 3: The process of embodiment 1 or embodiment 2, wherein themedium boiling fraction has two or more of the following properties:

-   -   a 5% boiling point temperature in the range from about 130° C.        to about 200° C.;    -   a 95% boiling point temperature in the range from about 400° C.        to about 600° C.;    -   a hydrogen content in the range from about 12 wt % to about 14        wt %;    -   a BMCI in the range from about 5 to less than 50;    -   an API gravity of in the range from about 10° to about 40°;    -   a sulfur content in the range from about 1000 ppm to about 10000        ppm;    -   a nitrogen content in the range from about 1 ppm to about 100        ppm;    -   a viscosity, measured at 40° C., of greater than 1 cSt;    -   less than 5 wt % MCRT; and    -   less than 50 ppm total metals.

Embodiment 4: The process of any one of embodiments 1-3, wherein thehigh boiling residue fraction has two or more of the followingproperties:

-   -   a 5% boiling point temperature in the range from about 400° C.        to about 600° C.;    -   a hydrogen content of less than 12 wt %;    -   a BMCI of greater than 50;    -   an API gravity of less than 10°;    -   a sulfur content of greater than 10000 ppm;    -   a nitrogen content of greater than 100 ppm;    -   a viscosity, measured at 100° C., of greater than 100 cSt;    -   greater than 5 wt % MCRT; and    -   greater than 50 ppm total metals.

Embodiment 5: The process of any one of embodiments 1-4, wherein anoverall chemicals production of the feedstock is at least 65 wt %, basedon the total amount of olefins produced as compared to a total feedstockfeed rate.

Embodiment 6: The process of any one of embodiments 1-5, whereindestructively hydrogenating the high boiling residue fraction comprisesconverting hydrocarbons in the high boiling residue fraction to one ormore naphtha range hydrocarbons.

Embodiment 7: The process of any one of embodiments 1-6, wherein theportion of the high boiling residue fraction not converted into naphtharange hydrocarbons is separated in the second integrated separationdevice as the ultra-low sulfur fuel oil.

Embodiment 8: The process of embodiment 1, further comprisinghydrocracking the medium boiling fraction.

Embodiment 9: The process of embodiment 8, further comprising combiningthe medium boiling fraction and the hydroprocessed fraction prior tohydrocracking in the second hydroprocessing system.

Embodiment 10: The process of embodiment 1, wherein destructivelyhydrogenating the high boiling residue fraction comprises contacting thehigh boiling residue fraction with a residue desulfurization catalyst.

Embodiment 11: The process of embodiment 1, further comprising feeding aportion of the medium boiling fraction to an aromatics complex toproduce aromatics and feeding a second, heavier portion of the mediumboiling fraction to the steam cracker.

Embodiment 12: The process of embodiment 8, wherein hydrocracking themedium boiling fraction comprises converting hydrocarbons in the mediumboiling fraction to primarily naphtha range hydrocarbons.

Embodiment 13: A system for converting whole crudes and other heavyhydrocarbon streams to produce olefins, the system comprising:

-   -   a first integrated separation device for separating a        hydrocarbon feedstock into at least a light boiling fraction, a        medium boiling fraction, and a high boiling residue fraction;    -   a first hydroprocessing system configured for hydrotreating the        high boiling residue fraction and producing a hydrotreated        effluent;    -   a second integrated separation device configured for separating        the hydrotreated and hydrocracked effluent and producing an        ultra-low sulfur fuel oil and a hydroprocessed fraction;    -   a second hydroprocessing system configured for hydrocracking the        hydroprocessed fraction and producing a steam cracker        feedstream;    -   a steam cracker unit for converting the steam cracker feedstream        and the light boiling fraction into one or more light olefins        and a pyrolysis oil.

Embodiment 14: The system of embodiment 13, wherein the first integratedseparation device is configured to provide the light boiling fractioncomprising hydrocarbons having a boiling point of less than about 160°C. and the high boiling residue fraction comprising hydrocarbons havinga boiling point greater than about 160° C.

Embodiment 15: The system of embodiment 13, where the first integratedseparation device is configured to provide the light boiling fractioncomprising hydrocarbons having a boiling point of less than about 160°C., the medium boiling fraction comprising hydrocarbons boiling in therange from about 160° C. to about 490° C., and the high boiling residuefraction comprising hydrocarbons having a boiling point of greater thanabout 490° C.

Embodiment 16: The system of embodiment 15, further comprising a flowline configured to feed the medium boiling fraction to the secondhydroprocessing system.

Embodiment 17: The system of embodiment 16, further comprising a mixingunit or a t-junction configured for combining the medium boilingfraction and the hydroprocessed fraction upstream of the secondhydroprocessing system.

Embodiment 18: The system of embodiment 16, wherein the secondhydroprocessing system comprises a catalyst configured for convertinghydrocarbons in the hydroprocessed fraction and the medium boilingfraction to primarily naphtha range hydrocarbons.

Embodiment 19: A process for the thermal conversion of crude oils tochemicals, the system comprising:

-   -   hydrotreating and/or hydrocracking a whole crude in a        conditioning unit comprising one or more reactors;    -   feeding the hydrotreated and/or hydrocracked whole crude to a        steam cracker for converting the hydrotreated and/or        hydrocracked whole crude into chemicals including ethylene,        propylene, and butenes;    -   wherein the conditioning unit and the steam cracker are        configured to have aligned run times.

Embodiment 20: The process of embodiment 19, wherein the whole crude isa condensate hydrocarbon with a boiling range up to 565° C.

Embodiment 21: A process for converting whole crudes and other heavyhydrocarbon streams to produce olefins and/or aromatics, the processcomprising:

-   -   separating a hydrocarbon feedstock into at least light boiling        fraction and a high boiling residue fraction;    -   destructively dehydrogenating the high boiling residue fraction        in a hydroproces sing system to produce a hydrotreated effluent;    -   feeding the light boiling fraction and the hydrotreated effluent        to a steam cracker to convert hydrocarbons therein into one or        more light olefins and a pyrolysis oil.

Embodiment 22: The process of embodiment 21, wherein the light boilingfraction has two or more of the following properties:

-   -   a 95% boiling point temperature in the range from about 130° C.        to about 200° C.;    -   a hydrogen content of at least 14 wt %;    -   a BMCI of less than 5;    -   an API gravity of greater than 40°;    -   a sulfur content of less than 1000 ppm;    -   a nitrogen content of less than 10 ppm;    -   a viscosity, measured at 40° C., of less than 1 cSt;    -   less than 1 wt % MCRT; and    -   less than 1 ppm total metals.

Embodiment 23: The process of any one of embodiments 21-22, wherein thehigh boiling residue fraction has two or more of the followingproperties:

-   -   a 5% boiling point temperature in the range from about 200° C.+;    -   a hydrogen content of less than 12 wt %;    -   a BMCI of greater than 50;    -   an API gravity of less than 10°;    -   a sulfur content of greater than 10000 ppm;    -   a nitrogen content of greater than 100 ppm;    -   a viscosity, measured at 100° C., of greater than 100 cSt;    -   greater than 5 wt % MCRT; and    -   greater than 50 ppm total metals.

Embodiment 24: The process of any one of embodiments 21-23, wherein anoverall chemicals production of the feedstock is at least 65 wt %, basedon the total amount of olefins produced as compared to a total feedstockfeed rate.

Embodiment 25: The process of any one of embodiments 21-24, whereindestructively hydrogenating the high boiling residue fraction comprisesconverting hydrocarbons in the high boiling residue fraction to one ormore naphtha range hydrocarbons.

Embodiment 26: the process of embodiment 21, wherein the separatingcomprises

-   -   feeding a hydrocarbon feedstock into a heater, producing a        pre-heated hydrocarbon feedstock;    -   separating the pre-heated hydrocarbon feedstock in a separator        into a light boiling fraction and an intermediate fraction;    -   feeding the intermediate fraction back to the heater, producing        a heated intermediate fraction;    -   feeding a hydrogen stream and the intermediate fraction to a hot        hydrogen stripper;    -   cooling the hot hydrogen stripper bottoms fraction via indirect        heat exchange against the intermediate fraction producing a high        boiling residue fraction.

Embodiment 27: A process for converting whole crudes and other heavyhydrocarbon streams to produce olefins and/or aromatics, the processcomprising:

-   -   separating a hydrocarbon feedstock into at least a light boiling        fraction and a high boiling residue fraction;    -   hydrocracking the high boiling residue fraction in a first        hydroprocessing system to produce a hydrotreated effluent;    -   separating the hydrotreated effluent in an integrated separation        device to produce an ultra-low sulfur fuel oil and a        hydroprocessed fraction;    -   destructively hydrogenating the hydroprocessed fraction in a        second hydroprocessing system to produce a steam cracker        feedstream;    -   feeding the steam cracker feedstream and the light boiling        fraction to a steam cracker to convert hydrocarbons therein into        one or more light olefins and a pyrolysis oil.

Embodiment 28: The process of embodiment 27, wherein the light boilingfraction has two or more of the following properties:

-   -   a 95% boiling point temperature in the range from about 130° C.        to about 200° C.;    -   a hydrogen content of at least 14 wt %;    -   a BMCI of less than 5;    -   an API gravity of greater than 40°;    -   a sulfur content of less than 1000 ppm;    -   a nitrogen content of less than 10 ppm;    -   a viscosity, measured at 40° C., of less than 1 cSt;    -   less than 1 wt % MCRT; and    -   less than 1 ppm total metals.

Embodiment 29: The process of any one of embodiments 17-28, wherein thehigh boiling residue fraction has two or more of the followingproperties:

-   -   a 5% boiling point temperature in the range from about 200° C.+;    -   a hydrogen content of less than 12 wt %;    -   a BMCI of greater than 50;    -   an API gravity of less than 10°;    -   a sulfur content of greater than 10000 ppm;    -   a nitrogen content of greater than 100 ppm;    -   a viscosity, measured at 100° C., of greater than 100 cSt;    -   greater than 5 wt % MCRT; and    -   greater than 50 ppm total metals.

Embodiment 30: The process of any one of embodiments 27-29, wherein anoverall chemicals production of the feedstock is at least 65 wt %, basedon the total amount of olefins produced as compared to a total feedstockfeed rate.

Embodiment 31: The process of any one of embodiments 27-30, whereindestructively hydrogenating the high boiling residue fraction comprisesconverting hydrocarbons in the high boiling residue fraction to one ormore naphtha range hydrocarbons.

Embodiment 32: The process of any one of embodiments 27-31, wherein theportion of the high boiling residue fraction not converted into naphtharange hydrocarbons is separated in the second integrated separationdevice as the ultra-low sulfur fuel oil.

Embodiment 33: the process of embodiment 27, wherein the separatingcomprises

-   -   feeding a hydrocarbon feedstock into a heater, producing a        pre-heated hydrocarbon feedstock;    -   separating the pre-heated hydrocarbon feedstock in a separator        into a light boiling fraction and an intermediate fraction;    -   feeding the intermediate fraction back to the heater, producing        a heated intermediate fraction;    -   feeding a hydrogen stream and the intermediate fraction to a hot        hydrogen stripper;    -   cooling the hot hydrogen stripper bottoms fraction via indirect        heat exchange against the intermediate fraction producing a high        boiling residue fraction.

Embodiment 34: A process for converting whole crudes and other heavyhydrocarbon streams to produce olefins and/or aromatics, the processcomprising:

-   -   Hydrotreating the whole crude in a hydroprocessing system to        produce a hydrotreated effluent;    -   feeding the hydrotreated effluent to a steam cracker to convert        hydrocarbons therein into one or more light olefins and a        pyrolysis oil.

Embodiment 35: The process of embodiment 34, wherein an overallchemicals production of the feedstock is at least 65 wt %, based on thetotal amount of olefins produced as compared to a total feedstock feedrate.

Embodiment 36: A process for converting whole crudes and other heavyhydrocarbon streams to produce olefins and/or aromatics, the processcomprising:

-   -   separating a hydrocarbon feedstock into a light boiling fraction        and a high boiling residue fraction;    -   hydrocracking the high boiling residue fraction in a        hydroprocessing system to produce a hydrotreated effluent;    -   feeding the hydrotreated effluent and the light boiling fraction        to a steam cracker to convert hydrocarbons therein into one or        more light olefins and a pyrolysis oil.

Embodiment 37: The process of embodiment 34, wherein an overallchemicals production of the feedstock is at least 65 wt %, based on thetotal amount of olefins produced as compared to a total feedstock feedrate.

While the disclosure includes a limited number of embodiments, thoseskilled in the art, having benefit of this disclosure, will appreciatethat other embodiments may be devised which do not depart from the scopeof the present disclosure.

We claim:
 1. A system for converting whole crudes and other heavyhydrocarbon streams to produce olefins and aromatics, the systemcomprising: a first integrated separation device for separating ahydrocarbon feedstock into at least a light boiling fraction, a mediumboiling fraction, and a high boiling residue fraction; a firsthydroprocessing system configured for hydrotreating the high boilingresidue fraction and producing a hydrotreated effluent; a secondintegrated separation device configured for separating the hydrotreatedand hydrocracked effluent and producing an ultra-low sulfur fuel oil anda hydroprocessed fraction; a second hydroprocessing system configuredfor hydrocracking the hydroprocessed fraction and producing a steamcracker feedstream; a steam cracker unit for converting the steamcracker feedstream and the light boiling fraction into one or more lightolefins and a pyrolysis oil, a separation system for separating thepyrolysis oil into a heavy pyrolysis gasoline fraction and a lightpyrolysis gasoline fraction; and an aromatics unit for receiving thelight pyrolysis gasoline fraction and converting at least a portion ofthe light pyrolysis gasoline fraction to aromatics.
 2. The system ofclaim 1, wherein the first integrated separation device is configured toprovide the light boiling fraction comprising hydrocarbons having a 95%boiling point temperature in the range from about 130° C. to about 200°C. a hydrogen content of at least 14 wt %, a BMCI of less than 5, an APIgravity of greater than 40°, a sulfur content of less than 1000 ppm, anitrogen content of less than 10 ppm, a viscosity, measured at 40° C.,of less than 1 cSt, less than 1 wt % MCRT, and less than 1 ppm totalmetals, and the high boiling residue fraction comprising hydrocarbonshaving a 5% boiling point temperature of about 200° C. a hydrogencontent in the range from about 12 wt % to about 14 wt %, an API gravityof up to about 40°, a viscosity, measured at 40° C., of greater than 1cSt, greater than 1 wt % MCRT, and greater than 10 ppm total metals. 3.The system of claim 1, where the first integrated separation device isconfigured to provide the light boiling fraction comprising hydrocarbonshaving a 95% boiling point temperature in the range from about 130° C.to about 200° C., a hydrogen content of at least 14 wt %, a BMCI of lessthan 5, an API gravity of greater than 40°, a sulfur content of lessthan 1000 ppm, a nitrogen content of less than 10 ppm, a viscosity,measured at 40° C., of less than 1 cSt, less than 1 wt % MCRT, and lessthan 1 ppm total metals, the medium boiling fraction comprisinghydrocarbons having a 5% boiling point temperature in the range fromabout 130° C. to about 200° C. and a 95% boiling point temperature inthe range from about 400° C. to about 600° C., a hydrogen content in therange from about 12 wt % to about 14 wt %, a BMCI in the range fromabout 5 to less than 50, an API gravity of in the range from about 10°to about 40°, a sulfur content in the range from about 1000 ppm to about10000 ppm, a nitrogen content in the range from about 1 ppm to about 100ppm, a viscosity, measured at 40° C., of greater than 1 cSt, less than 5wt % MCRT, and less than 50 ppm total metals, and the high boilingresidue fraction comprising hydrocarbons having a 5% boiling pointtemperature in the range from about 400° C. to about 600° C., a hydrogencontent of less than 12 wt %, a BMCI of greater than 50, an API gravityof less than 10°, a sulfur content of greater than 10000 ppm, a nitrogencontent of greater than 100 ppm, a viscosity, measured at 100° C., ofgreater than 100 cSt, greater than 5 wt % MCRT, and greater than 50 ppmtotal metals.
 4. The system of claim 3, further comprising a flow lineconfigured to feed the medium boiling fraction to the secondhydroprocessing system.
 5. The system of claim 4, further comprising amixing unit or a t-junction configured for combining the medium boilingfraction and the hydroprocessed fraction upstream of the secondhydroprocessing system.
 6. The system of claim 4, wherein the secondhydroprocessing system comprises a catalyst configured for convertinghydrocarbons in the hydroprocessed fraction and the medium boilingfraction to primarily steam crackable products.